1. Technical Field
The present technology relates to an improved process for recovery of hydrocarbons from a porous formation or reservoir. More particularly, the technology relates to a multi-stage process for enhanced recovery of high viscosity oil from low temperature subterranean reservoirs by applying enhanced chemical techniques to produce the oil.
2. Description of Related Art
In recent years there has been an increase in the price of crude oil, albeit that the increase has not been steady, but has been subject to the vagaries of politics, economics of supply and demand, speculation, and a host of factors. In general, however, few would argue that the price is not on a general upward trend. The price increase seems to coincide with steady and often spectacular economic growth of nations that had not previously been major consumers of energy, and particularly not of transportation fuels. The demand from these growing nations appears to place a strain on supply and has been cited as a contributing factor, at least, of the general increase in the price of oil over recent years.
The availability of oil reserves and oil production (supply) depends to a large extent on the price that consumers are willing to pay for the oil and/or products derived from the oil. As the price increases, reserves that had not previously been attractive to exploit, from a purely economic standpoint, become more attractive to produce. For example, very deep-off shore wells are expensive and require a high oil price to justify the capital expenditure and the risks associated with drilling miles under the ocean floor. Modern seismic technologies might minimize the risk of a “dry hole” costing tens of millions of dollars to drill, but the risk of loss is not zero. Moreover, while drilling might be economically justified at a projected price, based on the best available data, that projection may yet turn out to be wrong for a number of reasons, including market forces, advances in other technologies (e.g. alternative energy, conservation technologies), an unexpected global economic downturn, etc. Thus anticipated profits may turn into realized losses.
At the outset, the cheapest sources are usually large oil fields on land that produce prodigious amounts of sweet (low sulfur content), light oil (i.e. oil having a low viscosity, and low specific gravity or high API), under reservoir pressure. The discovery of new oil fields that meet this description, and that are in politically stable regions of the world to facilitate exploitation, appears to be dwindling. Alternatives to these ideal sources are reservoirs that require assistance by pumping out the oil, which adds operating costs. Other alternatives are producing sour (high sulfur) crude oils or heavy (low API) crude oils which are generally more expensive to refine into transportation fuels. Such crude oils also have a relatively lower inherent capability to be processed into transportation fuels as compared to sweet, light crude oils. Indeed, to ease processing severities at refineries, light sweet crude oil is often blended with heavy, sour crude oil to form a blend that facilitates processing into transportation fuels.
When prices continue to increase, yet more techniques for oil production become economically viable. For example, a significant proportion of the original oil in place in many oil-bearing subterranean formations remains in place after primary and secondary (pumping-assisted) production. With a sufficiently high market price, recovery of such residual oil becomes viable. Formations may be of such non-uniformity as to porosity, that some residual oil is trapped in hard-to-reach zones of the reservoir. Many factors affect the proportion of oil that is readily removed from a reservoir under self-pressure and under pumping conditions.
At a sufficiently high price, recovery of much heavier, high viscosity oil reserves may also become viable. These reservoirs may be untouched and may even be accessible, and/or in shallow formations, but may have required such expensive treatment to remove oil as to not be economically viable. Moreover these oils may not have the best refining properties for making high value transportation fuels, for example. The main factors affecting the production of high viscosity crude oils, aside from global political factors, are simply the market price for the particular kind of oil, and the costs of recovering the oil.
Over more recent years, as the price of oil has generally increased (from the low prices of the early 1980s) many techniques have been developed to recover oil that might not have been viable to recover at lower prices. Often, these techniques are all referred to as enhanced oil recovery (“EOR”) techniques. These techniques are often customized for a particular reservoir, the nature of the oil to be recovered, its market price, and the costs of recovery, which may include not only direct EOR costs but also environmental remediation, protection, maintenance and related costs.
An example of an EOR used to recover heavy oil or residual oil, includes the step of heating underground formations to reduce the viscosity of the oil and improve its ability to flow through the reservoir to a production well. The relationship between oil temperature (y-axis) and kinematic viscosity (centistokes, x-axis) is illustrated in FIG. 1. The graph is logarithmic and indicates the large reductions in kinematic viscosity achievable through increases in temperature for a wide range of crude oils. For example, for California (heavy) crude (top line of graph) increasing the temperature from 100 to 140° F. decreases the viscosity from about 80,000 centistokes to about 5,000 centistokes. This is a 94% reduction for 40° F. increase in temperature. In contrast, heating paraffin (lowest line of graph) from 100 to 140° F. decreases viscosity from 9 to 5 centistokes, or about 44%. This is significant, but clearly heating a heavy crude oil has a much more significant effect on both absolute, as well as percentage, viscosity reduction.
There are many variations of applying heat to a reservoir, including cyclic steam injection, continuous steam injection, or even hot water injection. Each has advantages and disadvantages in specific situations. Since hot water is not as hot as steam, heat losses are less with hot water injection. But, steam having much higher thermal energy due to the latent heat of conversion from water to steam, is able to apply far more heat per pound injected. Steam, having a lower viscosity that water has a greater tendency to “channel” or “finger,” by following a path of least flow resistance. This means that regions outside of this flow path may not be exposed to the steam, whereas these regions may be accessible to hot water. Heat may also travel through the formations of the reservoir by conduction and convection, aside from heat transfer from the hot fluid directly to the formations that it contacts.
Another EOR technique is gas injection. In this technology, gases may be used to expand in a reservoir and thereby push additional oil to a production well. Or, gases that dissolve in the oil to lower its viscosity and improve its flow rate may be injected into the reservoir. One of the gases that may be used is carbon dioxide, and often in the form of a supercritical fluid. As a supercritical fluid, carbon dioxide is able to extract (or “leach”) oil from formations, commingle with oil in the reservoir, and sweep the extracted and commingled oil to the production well.
As a further alternative, chemical injection and extraction may be used as an EOR technology. In general, the chemical technologies include polymer flooding, surfactant-polymer flooding (“SP”), and alkaline-surfactant-polymer flooding (“ASP”) of the subterranean reservoir.
Polymer flooding includes injecting an aqueous (usually) solution of a polymer into a subterranean reservoir formation. Polymers provide “mobility control” within the reservoir. The addition of the polymer increases the viscosity (i.e., reduces the “mobility”) of the solution in which it is dissolved or carried, and thereby minimizes the tendency to “channeling” or “fingering” by seeking the easiest path (path of least flow resistance) through the underground formations. The sought-after oil most likely will be off path of least flow resistance and in regions of the reservoir that are not so easily approached, because of many structural reasons, including for example low porosity, making the oil inaccessible to a low viscosity (high mobility) fluid. By reducing the mobility of the injected solution, the polymer solution minimizes channeling of the water through the reservoir, spreading the flow more broadly horizontally and vertically throughout the reservoir formations. Thus, it potentially provides a more efficient sweep of any remaining oil in the reservoir.
The most commonly used polymers are hydrolyzed polyacrylamides (HPAM), which are polyelectrolytes having a molecular weight in the range 1 to 20 million, or 10 to 25 million. However, many variables may indicate an alternative choice. The polymer concentration may be adjusted to achieve a desired mobility for the desired extent of formation penetration and flooding.
Going a step further, adding a surfactant to the polymer solution reduces the inter-facial tension (IFT) at the oil-water interface and permits higher oil recovery. (IFT is a significant parameter, as discussed in more detail below). Surfactant molecules are characterized in having a backbone, with a lipophilic (oil-soluble) moiety and a hydrophilic (water-soluble) moiety attached to the backbone. Generally, surfactants are classified as non-ionic, cationic, anionic or zwitterionic. In the EOR processes, the tendency has been to use non-ionic or anionic surfactants. The anionic surfactants exhibit a negatively charged region that reduces its attraction to silica, clays, and other components of reservoir formations, which are also negatively charged. As a result, there is low retention of these surfactants on reservoir solids.
In the reservoir, lypophilic moieties of the injected surfactant interact with the oil (often to form a micro-emulsion, as discussed in more detail below). The overall effect is to enhance commingling of the injected surfactant-polymer solution and the oil and thereby improve oil recovery at the production well. The surfactant-polymer formulation may be adjusted for viscosity and the level of surfactant activity desired. Micro-emulsions may interfere with surfactant performance. Micro-emulsions associated with heavy crude oil are often viscous and exhibit non-Newtonian flow characteristics. These properties may adversely affect surfactant performance, injected liquid distribution in the formation, and oil recovery. Generally, to resolve any micro-emulsion issues, a co-solvent is often added to the injected surfactant-polymer formulation. However, this increases the costs of the EOR processes.
The most commonly used surfactants include ether sulfates, the stabilized ether sulfates (above 25° C.), internal olefin sulfates (IOS), and alcohol alkoxy sulfonates. In the latter, the hydrophilic-lipophilic balance may be controlled by the ratio of ethylene oxide to propylene oxide in the molecule.
It has been noted that high viscosity, heavy oils, in particular, are often acidic. The acidic nature of such oil deposits can be neutralized by alkaline chemicals to form in situ soaps. Therefore, when there are acids in the crude oils, such as naphthalenic acids, then flooding the reservoir with a solution that includes an alkaline-surfactant-polymer (ASP) formulation converts at least some of these acids in the oil to soaps. This reduces the IFT and could thereby increase oil production. Moreover, loss of surfactant due to adsorption (onto the reservoir solids) is reduced in the high pH conditions created by the alkali. In this formulation, there are several variables that may be tailored including the concentrations of the alkaline medium (and which particular medium, e.g. sodium carbonate, sodium hydroxide, sodium ortho-silicate, etc.) the nature and concentration of the polymer and surfactant and the desired viscosity/mobility of the solution.
In a further improvement to the ASP processes, a co-solvent is added to improve surfactant performance. The improvement can result from several effects: a reduction in micro-emulsion viscosity, disruption of gel and crystal formation, improving coalescence of the micro-emulsion, and improving aqueous stability of the surfactant solutions. Typically, a low molecular weight alcohol, such as iso-butanol is used as the co-solvent. The appropriate concentration of alcohol depends upon temperature, and on a range of other variables, often requiring a systemic study to determine. Moreover, alcohols, having low flash points, may also introduce flammability issues in the field. Therefore, higher molecular weight alcohols or ethers, such as diethylene glycol butyl ether (DGBE), are preferred.
A challenging issue, briefly mentioned in the outline above, is the presence of highly viscous micro-emulsions in highly viscous heavy crude oil reservoirs. A micro-emulsion is generally defined as a thermodynamically stable liquid phase formed when oil, water and a surfactant commingle to form a liquid containing all three components. Micro-emulsions are characterized as Type I, Type II, or Type III. A Type I micro-emulsion is an oil-in-water emulsion where a portion of the oil is solubilized by surfactant micelles. Type II is a water-in-oil emulsion where a portion of the water has been solubilized in the surfactant micelles. Type III is a bi-continuous emulsion containing both water and oil solubilized in the surfactant micelles. Being thermodynamically stable, these micro-emulsions do not readily break down into separate oil and water phases. But, they can shift from one type to another depending upon factors, such as, for example, the salinity, temperature, pressure, surfactant nature and concentration, the amount of oil and the equivalent carbon alkane number (EACN) of the oil. A Type III micro-emulsion is preferable over the other types because it has the highest solubility ratios (more water and oil are solubilized with the surfactant), which also gives the lowest IFT, thereby suggesting it is more efficient in oil recovery. Generally, a shift from Type I to Type III can be achieved by increasing salinity, increasing surfactant lipophilicity, decreasing pressure, decreasing temperature (for anionic surfactants). However, the predominant parameter is the EACN of the oil. Thus, adding a light hydrocarbon (e.g., methane or another alkane having from 2 to 10 carbon atoms) reduces the EACN number of the crude oil allowing a transition from Type Ito Type III.The solubilizing properties of surfactants play an important role in micro-emulsion formation. As mentioned before, one of the factors that influence surfactant-oil interaction is the inter-facial tension (“IFT”) which is a parameter that relates directly to solubilization. Generally, a good system with a high solubilization ratio would have a large Type III micro-emulsion phase and would give an IFT of 10−3 dyne/cm, which is required to displace the oil down to a residual saturation near zero.
It is believed that both the IFT and the micro-emulsion viscosity are significant variables in EOR. Micro-emulsion viscosity is significant in surfactant retention in the formations of the reservoir, pressure gradients, sweep efficiency, and chemical slug mobility. The viscosity of the micro-emulsion often has a maximum near the point where the oil and water concentrations in the emulsion are about equal. Reduction in micro-emulsion viscosity would reduce the possibility of phase trapping and surfactant retention in the reservoir, and is therefore beneficial to an increase in oil recovery. However, these micro-emulsions are thermodynamically stable and reduction in their viscosity presents challenges.
As noted above, oil economics drives the applicability of oil recovery technologies so that once-unattractive sources become viable. It is well-known that there are relatively shallow reservoirs that contain highly viscous oils. The high viscosity of the oils presents a challenge to their extraction. And, the high viscosity and low proportion of lighter oil components, which are easily processed into transport fuels, also present an issue with regard to market price and refining. In many cases, these shallow reservoirs occur at a depth of less than 1,000 feet (330 meters). The high viscosity of the oil and the cold subterranean formation conditions present technical and economic challenges to the extraction of this oil, even as oil prices continue to rise.